Downhole Tool Actuation

ABSTRACT

In one aspect of the invention, a downhole tool string component has at least one end adapted to connect to an adjacent tool sting component and a bore adapted to accommodate a flow of drilling fluid. A turbine is disposed within the bore and an actuating assembly is arranged such that a clutch may mechanically connect and disconnect with the turbine.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.12/391,358 filed on Feb. 24, 2009.

BACKGROUND OF THE INVENTION

This invention relates to actuating downhole tools, specifically toolsfor oil, gas, geothermal, and horizontal drilling. Downhole toolactuation is often accomplished by dropping a ball down the bore of thedrill string to break shear pins, which, upon breaking, frees a valve toopen actuating a tool such as a reamer. Once the pins are broken, thedrill string must be removed from the hole to replace them. Otherdisadvantages, such as an inability to reset the tool while stilldownhole, are inherent in this type of design.

BRIEF SUMMARY OF THE INVENTION

In one aspect of the present invention, a downhole tool string componenthas at least one end with an attachment to an adjacent tool stringcomponent and a turbine disposed in a drilling mud bore. An actuatingassembly is arranged in the bore such that when actuated a clutchmechanically connects the assembly to the turbine and when deactivatedthe assembly and turbine are mechanically disconnected.

The actuating assembly may move a linear translation mechanism, whichmay include a sleeve. The sleeve may have at least one port that isadapted to align with a channel formed in a wall of the bore when thesleeve moves. The actuating assembly may control a reamer, a stabilizerblade, a bladder, an in-line vibrator, an indenting member in a drillbit, or combinations thereof.

The actuating assembly may comprise a collar with a guide slot around acam shaft with a pin or ball extending into the slot. When the collarmoves axially, the cam shaft rotates due to the interaction between thepin or ball and the slot. The cam shaft may be in mechanicalcommunication with the shaft and adapted to activate the switch. The camshaft may be in communication with a switch plate adapted to engage aplurality of gears. The actuating assembly may comprise at least onesolenoid adapted to move a translation member in communication with theswitching mechanism.

In some embodiments, the actuating assembly comprises a switchingmechanism adapted to rotate a gear set in multiple directions.

The clutch may be a centrifugal clutch adapted to rotate with theturbine. The clutch may have at least one spring loaded contact withadapted to connect the clutch to the shaft. The actuating assembly maybe triggered by increase in turbine rotational velocity, a decrease inturbine velocity, or a combination thereof. In some embodiments, theclutch may be controlled by a solenoid. The clutch may also becontrolled over a wired drill pipe telemetry system, a closed loopsystem, or combinations thereof.

In another aspect of the present invention, a downhole tool stringcomponent comprises at least one end with an attachment to an adjacenttool string component and a drilling mud bore. A turbine is disposedwithin the bore that is in mechanical communication with a linearactuator that is aligned with a central axis of the tool stringcomponent.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective diagram of an embodiment of a drill stringsuspended in a borehole.

FIG. 2 a is a perspective diagram of an embodiment of a reamer in a toolstring.

FIG. 2 b is a cross-sectional diagram of an embodiment of a reamer in atool string.

FIG. 3 is a cross-sectional diagram of an embodiment of a downhole drillstring component.

FIG. 4 is a cross-sectional diagram of an embodiment of a downhole drillstring component.

FIG. 5 is a cross-sectional diagram of an embodiment of a downhole drillstring component.

FIG. 6 is a perspective diagram of an embodiment of a portion of adownhole drill string component.

FIG. 7 is a perspective diagram of an embodiment of a portion of adownhole drill string component.

FIG. 8 a is a cross-sectional diagram of an embodiment of a downholedrill string component.

FIG. 8 a is a cross-sectional diagram of an embodiment of a downholedrill string component.

FIG. 9 is a cross-sectional diagram of an embodiment of a downholepacker.

FIG. 10 a is a perspective cross section of an embodiment of a downholedrill string component.

FIG. 10 b is a perspective cross section of an embodiment of a downholedrill string component.

FIG. 11 a is a perspective cut-away of an embodiment of a weightedclutch.

FIG. 11 b is a perspective cut-away of an embodiment of a weightedclutch.

FIG. 12 a is a perspective diagram of an embodiment of a downhole drillstring component.

FIG. 12 b is a perspective diagram of an embodiment of a downhole drillstring component.

FIG. 13 a is a cross-sectional diagram of an embodiment of a drill bit.

FIG. 13 b is a cross-sectional diagram of an embodiment of a drill bit.

FIG. 14 is a cross-sectional diagram of an embodiment of a reamer.

FIG. 15 is a cross-sectional diagram of an embodiment of a stabilizer ina drill string component.

FIG. 16 is a perspective diagram of an embodiment of a vibrator.

FIG. 17 is a perspective diagram of an embodiment of a downhole drillstring component.

FIG. 18 a is a perspective diagram of an embodiment of a turbine.

FIG. 18 b is a perspective diagram of an embodiment of a turbine.

DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED EMBODIMENT

FIG. 1 is a perspective diagram of an embodiment of a drill string 100suspended by a derrick 108 in a bore hole 102. A drilling assembly 103is located at the bottom of the bore hole 102 and comprises a drill bit104. As the drill bit 104 rotates downhole the drill string 100 advancesfarther into the earth. The drill string 100 may penetrate soft or hardsubterranean formations 105. The drilling assembly 103 and/or downholecomponents may comprise data acquisition devices adapted to gather data.The data may be sent to the surface via a transmission system to a dataswivel 106. The data swivel 106 may send the data to the surfaceequipment. Further, the surface equipment may send data and/or power todownhole tools, the drill bit 104 and/or the drilling assembly 103.

FIG. 2 a is a perspective diagram of an embodiment of a downhole drillstring component 201 with a reamer 200. The reamer 200 may be adapted toextend into and retract away from a borehole wall. While against theborehole wall, the reamer 200 may be adapted to enlarge the diameter ofthe borehole larger than accomplished by the drill bit at the front ofthe tool string component.

FIG. 2 b is a cross-sectional diagram of an embodiment of a reamer 200.A sleeve 202 located within the bore 204 of the tool sting component 201may comprise ports 203. The ports 203 may be adapted to divert drillingmud from the bore 204 when aligned with openings 250 formed in the borewall. The diverted drilling mud may engage a piston 205 located in achamber 251 otherwise isolated from the bore 204, after which thedrilling mud is re-diverted back into the bore 204 of the tool stringcomponent 201. As the piston 205 extends, it may push the reamer 200outward. A ramp formed in the reamer body may cause the reamer 200 toextend radially as an axial force from the piston 205 is applied. Thepiston 205 and reamer 200 may stay extended by a dynamic force from theflowing drilling mud. The reamer body may be in mechanical communicationwith a spring 206 or other urging mechanism adapted to push the reamer200 back into a retracted position in the absence of the dynamicdrilling mud force. A reamer that may be compatible with the presentinvention with some modifications, is disclosed in U.S. Pat. No.6,732,817 to Smith International, which is herein incorporated byreference for all that it contains.

When the sleeve 202 is moved such that the ports 203 and openings 250misalign, the dynamic force is cut off and the reamer 200 retracts. Inother embodiments, a pause in drilling mud flow may also cause thereamer 200 to retract. The sleeve 202 may be moved to realign andmisalign on command to control the position of the reamer 200. In someembodiments, the sleeve 202 is adapted to partially align with theopenings 250, allowing a fluid flow less than its maximum potential toengage the piston 205, and extending the reamer 200 less than itsmaximum diameter.

FIG. 3 is a cross-sectional diagram of an embodiment of a downhole drillstring component 201. The drill string component 201 may comprise anactuating assembly 333 adapted to move the sleeve 202 axially. In someembodiments, the actuating assembly is a linear actuator. The drillstring component 201 may also comprise a turbine 400 in mechanicalcommunication with the actuation assembly 333 wherein the turbine may beinvolved in triggering and/or powering the actuation assembly 333. Theactuation assembly 333 may engage or disengage a plurality of gears 304,such as a planetary gear system, adapted to move a linear screw member1004 connected to the sleeve 202.

FIGS. 4 and 5 disclose a turbine located in the drilling component'sbore. As drilling mud is passed down the drill string component 201, asindicated by the arrows 402, the drilling mud rotates a turbine 400. Theturbine 400 may be connected to a driving gear 410 disposed on the endof a shaft 401 opposing the turbine 400. The turbine 400 may be inmechanical communication with a centrifugal clutch 502 and when rotated,the turbine 400 rotates the centrifugal clutch 502. When rotating fastenough, the centrifugal clutch 502 engages a mount 501 causing the mountto rotate with the turbine. As the mount 501 is rotated, the weights 555attached to one end of a pivotally attached bracket 300 may be forcedoutward away from the central axis of the drill string component 201while the other end of the bracket 300 moves to push down on a collar503 located below the mount 501. The collar 503 may comprise a guide pin557 which interacts with a guide slot 558 formed in a cam housing. Whenthe collar 503 is forced axially it may rotate the cam 556. The rotationof the cam 556 may move a switch plate 504 adapted to selectively placethe turbine driving gear in contact with a gear set 304. When activatedthe gear set may transfer torque from the turbine to a linear screwmember 1004 attacked to the sleeve 202.

The guide slot may comprise sections that cause the collar to move in afirst direction and other sections that cause the collar to move in anopposing direction. The direction of the collar will dictate how thegear engages the gear set. In a preferred embodiment, the gear set is aplanetary gear set that may control the direction that the gears rotate.A clockwise or counterclockwise rotation of the plurality of gears maydetermine the forward or backward axial movement of the linear screwmember 1004.

FIG. 6 discloses the switch plate 504 that moves the cam 556 as thecollar 503 is advanced axially. The switch plate 504, as shown in thisfigure, may be positioned such that the driving gear 410 becomes engagedwith a first set of gears 666 mounted to the switch plate 504. Theengagement of the gears set 304 may rotate a circular rack 567 thatdrives a secondary gear set 678 adapted to turn a linear screw member1004. The collar 503 may be in communication with a spring (not shown)adapted to urge the collar 503 back to its original axial position,after the turbine's rotational velocity substantially returns to itsoriginal rpm. Thus, disengaging the driving gear from the gear set andleaving the linear screw member in the resulting position.

When the turbine velocity changes again, the clutch will reengagecausing the collar 503 to re-interact with the pin in its guide slot.The slot is formed such that it will cause the cam to push driving gearinto a position that causes the gear set to retract the linear screwmember as shown in FIG. 7. Thus, the sleeve 202 (shown in FIG. 2 b)attached to the linear screw member may be moved to extend the reamerblade or to collapse the reamer assembly.

FIG. 8 a discloses an arrow 601 indicating the drilling mud flow throughthe drill string 201 which passes through the bore 204 of the drillstring 201 because the sleeve 202 and the ports 203 are misalignedblocking entrance to the drilling mud. FIG. 8 b discloses drilling mudpartially diverted through the ports 203 within the sleeve 202 into achannel 608 containing the piston 205. The engaged piston 205 moves thereamer 200 outward due to an inclined ramp formed in the blade(discussed in relation to FIG. 2 b).

FIG. 9 discloses a packer 800 that may be activated in a similar manneras the reamer described above.

FIGS. 10 a and 10 b are cross-sectional diagrams disclosing a solenoidactivated clutch. First and second opposing solenoids 1002, 1003 are inmechanical communication with a translation member 1050 guided by ashaft 401. The shaft is driven by the turbine which rotates a key gear1099, which is also translatable through the translation member. Whenactivated, either solenoid moves the key gear through the translationmechanism in its respective direction. Depending on the direction, thekey gear 1099 will engage either a forward gear 1098 or a reverse gear1097 which will drive the gear set to either extend or retract thelinear screw member as described above. The translation member maycomprise a length adapted to abut a barrier to control its travel. Thetranslation member may be biased, spring-loaded, or comprise an urgingmechanism adapted to return the member, and therefore the key gear, toan unengaged position in the absence of an activated solenoid.

The solenoid may be energized through either a local or remote powersource. A telemetry system, such as provided by wired drill pipe or mudpulse, may provide the input for when to activate which solenoid. Insome embodiments, a closed loop system may provide the input from asensed downhole parameter and control the actuation.

FIGS. 11 a and 11 b disclose a centrifugal clutch 502 which comprisesgrippers 1100 attached to springs 1101. When rotating fast enough, acentrifugal force may overcome the spring force and move grippers awayfrom the shaft 401. At lower rotational velocities the grippers 1100bear down on the shaft 401 rotationally locking them together. To engagethe centrifugal clutch 502 the flow of the drilling mud may be reduced;and to disengage the flow may be increased.

FIGS. 12 a and 12 b disclose an actuation assembly 333 comprising aturbine 400 connected to a shaft 401. When the centrifugal clutch 502 isengaged, the collar 503 may be pushed forward in a similar manner asdescribed above. In this embodiment, the collar 503 may comprise a balltrack 1111 adapted to receive a ball 1112 in communication with a cam556. As the collar 503 is pushed down, the cam 556 rotates which moves atranslation member 1050. Movement of the translation member causes thekey gear 1099 to engage with either a forward gear 1098 or reverse gear1097 as described above, which in turn either advances or retracts thelinear screw member.

FIG. 13 a is a cross-sectional diagram of an embodiment of a drill bit104. The drill bit 104 may comprise an actuating assembly 1500 patternedafter those described above. The assembly 1500 may be adapted to axiallymove an indenting member 1501 towards the cutting surface of the drillbit 104. The indenting member 1501 may be a steerable element, hammerelement, penetration limiter, weight-on-bit controller, sensor, probe,or combinations thereof. In the embodiment of FIG. 13 b, the indentingmember 1501 may be use to control the flow through a nozzle 1506disposed in the drill bit's face.

FIG. 14 is a cross-sectional diagram of an embodiment of a winged reamer200, which may be pivotally extended from the diameter of the drillstring component 201 by using the linear screw member 1004.

FIG. 15 discloses an actuation mechanism adapted to extend a stabilizerblade 1234. As the ports 203 in the sleeve 202 align with the openings250, the flow of the drilling mud may be partially diverted to a piston205 adapted to push a stabilizer 1234 towards a formation.

FIG. 16 discloses an in-line vibrator 1750 disposed within the bore ofthe drill string component 201. As the shaft 401 rotates due toactivation of the clutch an off-centered mass 1701 is rotated. In-linevibrators may reduce the drilling industry's dependence on jars whichviolently shake the entire drill string when the drill string getsstuck. An in-line vibrator may successfully free the drill pipeutilizing less energy than the traditional jars, preserving the life ofthe drill string components and its associated drilling instrumentation.In some embodiments, the use of the in-line vibrator may prevent thedrill string from getting stuck in the first place. The distal end 1751shaft 401 may be supported spider 1752

FIG. 17 discloses a turbine 400 with adjustable blades 1760. A solenoidmay be adapted to rotate a cam associated with the blades. By adjustingthe blade, the rpm of the turbine may be changed, and thereby activateor deactivate the centrifugal clutch.

FIGS. 18 a and 18 b disclose an embodiment of a turbine 400. The turbineblades 2000 may be configured to produce higher torque at a lower RPM.

Whereas the present invention has been described in particular relationto the drawings attached hereto, it should be understood that other andfurther modifications apart from those shown or suggested herein, may bemade within the scope and spirit of the present invention.

1. A downhole tool string component, comprising: at least one endcomprising an attachment to an adjacent tool string component and adrilling mud bore; and a turbine disposed within the bore is inmechanical communication with a linear actuator that is aligned with acentral axis of the tool string component; wherein the linear actuatoris in mechanical communication with the turbine through a planetary gearsystem.
 2. The component of claim 1, wherein the linear actuatorcomprises a screw section.
 3. The component of claim 1, wherein thelinear actuator comprises a sleeve with an outer diameter in substantialcontact with an inner diameter of the bore.
 4. The component of claim 3,wherein the sleeve comprises at least one port, wherein the at least oneport is adapted to align with a channel formed within a wall of thebore.
 5. The component of claim 1, wherein the linear actuator comprisesa collar with a guide slot disposed around a cam shaft with a pin orball extending into the slot, wherein when the collar moves axially, thecam shaft rotates due to the interaction between a pin and slot.
 6. Thecomponent of claim 5, wherein the cam shaft is in mechanicalcommunication with a shaft and adapted to activate a switch.
 7. Thecomponent of claim 5, wherein the cam shaft is in communication with aswitch plate adapted to engage a plurality of gears.
 8. The component ofclaim 1, wherein a clutch mechanically links the turbine to the linearactuator.
 9. The component of claim 1, wherein the linear actuatorcomprises a switching mechanism adapted to extend or retract theactuator.
 10. The component of claim 1, wherein the linear actuatorcontrols a reamer blade associated with the component.
 11. The componentof claim 1, wherein the linear actuator is triggered by an increase inturbine rotational velocity.
 12. The component of claim 1, wherein thelinear actuator is triggered by a decrease in turbine rotationalvelocity.
 13. The component of claim 1, wherein the linear actuator istriggered by an electric signal.
 14. The component of claim 1, whereinthe linear actuator controls a stabilizer blade position.
 15. Thecomponent of claim 1, wherein the linear actuator controls an indentingmember in a drill bit.
 16. The component of claim 1, wherein the linearactuator is controlled over a wired drill pipe.
 17. The component ofclaim 1, wherein the linear actuator is controlled through a closed loopsystem.